The EPMM model

Short overview

The EPMM is a unit commitment and economic dispatch model, which during the optimization process satisfies the electricity consumption needs in the modelled countries at minimum system cost considering the different types of costs and capacity constraints of the available power plants and cross-border transmission capacities.

The model minimizes the production cost of power plants to satisfy demand. These costs include start-up and shut-down costs of the power plants, the costs of production (mainly fuel and CO2 costs) and the costs which occur in case of curtailment of RES producers.

The model simultaneously optimizes all 168 hours of a modelled week, and as a result it determines the hours of the week in which power plants will operate and at what production level. The model is executed for all weeks of the given year, hence all 8760 hours are modelled. To increase the robustness of the model results, the model starts the weekly optimisation with Wednesdays and finishes with Tuesdays, to avoid that the fastest ramp-up period (Monday morning) would be the starting position of the optimisation. EPMM endogenously models 41 electricity markets in 38 countries.l

Power plants are represented at the unit/block level for each country and are divided into twelve technologies: biomass, hard-coal and lignite-based, geothermal, heavy fuel oil and light fuel oil, hydro, wind, PV, nuclear, natural gas and tide and wave power plants.

Key features of the EPMM model

Supply side representation in the model

Power plants are represented at the unit/block level for each country and are divided into twelve technologies: biomass, hard-coal and lignite-based, geothermal, heavy fuel oil and light fuel oil, hydro, wind, PV, nuclear, natural gas and tide and wave power plants.

All generation units are characterised by the following inputs: installed capacity, electrical efficiency and self-consumption. Short-run marginal costs of generation are calculated based on the country and technology specific fuel price, variable operational costs, taxes and CO2 emission costs. In case of dispatchable units (thermal, nuclear, storage hydropower and pumped storage) start-up costs are included. Renewable generation, other than biomass and storage hydropower, is included exogenously assuming zero marginal cost. Generation patterns are based on European weather data from 2006-2011 for PV and wind generation and 2008-2017 for hydro. These renewable technologies are non-dispatchable but can be curtailed at given costs.

Hydro generation is classified into three categories: run of river, pumped storage and reservoir. The reservoir hydro units can flexibly produce electricity while facing a maximum production constraint in aggregate for the entire week. This allows the model to capture the flexibility of hydro generation while placing a realistic limit to its overall contribution to the weekly and yearly electricity generation.

Demand side representation in the model

The power demand is an exogenous input to the hourly optimisation of the power system. Hourly demand data is derived from actual data of the year 2015, which is adjusted in the scenarios proportionally by assumed growth of the yearly consumption by 2030. The power demand is then met by the available power plant and import capacities subject to minimisation of the cost to serve demand.

Transmission grid representation

In the EPMM model each country represents one node, thus network constraints inside the countries are not considered. Cross-border transmission capacities are represented by net transfer capacities (NTCs) values, which put an upper limit to cross-border electricity trading. Exports and imports of power in a given hour may thus not exceed the NTC values. Imports and exports take place to minimise system cost and maximise security of supply.

Climate module & emissions granularity

Calculation of CO2 emissiions based on the production teschnolgy and fuel type

Socioeconomic dimensions

Being a sector specific model, it ahs limited socioeconomic dimension, as electricity demand ia exogenously driven.

Mitigation/adaptation measures and technologies

Power sector specific mitigation policies are feasible in the model, while more general climate polices need to be translated to sectoral targets.

Economic rationale and model solution

The model finds sectoral equilibrium in the electricity sector with aggregated demand and very detailed representation of the supply side. It simultaneously optimises the ENTSO-E 37 markets with considering trade opportunities represented by Net transfer capacities (NTC)

Key parameters

      - hours of a selected year are modelled;
      - The optimisation is conducted on a (rolling) weekly basis, with the objective to minimize system cost;
      - The hours within the week are interconnected: the operation of a power plant in a given hour has impact on its availability for the next hours. A yearly modelling sequence consists of 52 weekly optimisation steps, where the weeks are also connected: information on the last hourly operation of the production units of the modelled week is passed to the next week;
      - Power plants in the model are represented through a higher granularity (e.g. start-up cost, start-up time, and minimum utilisation rates) than typical power generation technology modelling characterisation (e.g. fuel type, fuel efficiency, and marginal cost);
      - EPMM covers the whole ENTSO-E power system, including EU member states and the Energy Community contracting parties.

Policy questions and SDGs

Key policies that can be addressed

Mitigation policies affecting the power sector including: taxation policies, quantitative targets, teschnology specific targets

Recent use cases

Paper DOI Paper Title Key findings Coexistence of nuclear and renewables in the V4 electricity system: Friends or enemies?

Realisation of all NPPs in V4 results in strong interaction of nuclear and vRES. Policies increasing interconnectivity can improve supply security in the V4. Promoting flexible operation of vRES and nuclear can reduce curtailments.

Regional cooperation reduces negative impacts of national energy planning South East Europe electricity roadmap – modelling energy transition in the electricity sectors

Energy policies in the South East Europe (SEE) region, both at the national and regional level, should focus on enabling renewable energy integration, as this will be a key component of the future energy mix.

EU and Energy Community policies should be incorporated into national energy planning to ensure that SEE countries embark on the energy transition process at an early stage.

Stranded costs should be carefully considered in decision-making on new fossil-fuel generation and gas network investment in order to avoid lock-in to carbon intensive technologies. If consistent decarbonization policy prevails, with a significant and persistent CO2 price signal, the role of natural gas remains transitory in the region.

The SEE region offers relatively cheap decarbonization options: the power sector can reduce GHG emissions above 94% by 2050 in the modelled scenarios. Assessment of the EU 10% interconnection target in the context of CO2 mitigation Results demonstrate that EU network development and climate policies are highly interconnected. Changing patterns in the interconnections of the EU electricity systems connect diverse generation portfolios and in a low carbon price environment could increase carbon emission at the community level. Policy makers should be aware of the interactions between these areas and design policy tools that also consider negative synergies.
Recent publications using the EPMM model